Static Var Compensators Protection Scheme Study

STATIC VAR COMPENSATORS PROTECTION SCHEME STUDY

CASE STUDY: MAHADIYA SUBSTATION SVC

By MOHAMMED ESSAM ELDIEN MOHAMMED ELAHAJ IBRAHEM INDEX NO 124082

Supervisor Dr. Elfadil Zakaria Yahia

A REPORT SUBMITTED TO University of Khartoum In partial fulfillment for the degree of B.Sc. (HONS) Electrical and Electronics Engineering (POWER ENGINEERING) Faculty of Engineering Department of Electrical and Electronics Engineering October 2017

DECLARATION OF ORGINALITY

I declare this report entitled “Static VAR compensators protection scheme study” is our own work except as cited in references. The report has been not accepted for any degree and it is not being submitted currently in candidature for any degree or other reward. Signature: ______Name: ______Date: ______

ACKNOWLEDGEMENT

First, all praise and thanks to Allah for providing me with this opportunity and granting me the capability to proceed successfully. To my mother, who brought to life and raised me to be the man that I am today. To my father who taught me the patience and self-confidence. I would like to express my very great appreciation to Dr. Elfadil Zakaria Yahia my supervisor for his valuable and constructive suggestions during the planning and development of this project Many thanks to my seniors ENG Azza Gasim alsaid for the great guidance and effort. Special thanks to my project partner for his hard work, support and cooperation.

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Abstract

In this project the protection scheme of the static VAR compensators of the MAHADYIA substation has been studied. Power system stability is very important, so SVC plays a major role in voltage regulation and improving the stability of the system due to its fast response and high capability. So, it’s very important to make sure that the SVC functions well under normal conditions in order for the electric power to be delivered with high quality to the consumers. Even if there is any abnormal condition, maintenance must be provided.

Main principles of operation for protection system beside the historical background of reactive power compensation and overview of static VAR compensators were discussed to illustrate the protection of the SVC.

Collecting the data required from MAHADIYA substation, and all calculations of the protective relays have been performed to study the protection scheme.

Simulation of this protection scheme has been performed using ETAP software and different scenarios of abnormal condition such as injecting three-phase fault were created to analyze the behavior of relays and circuit breakers.

The time of operation for relays to trip the circuit were found suitable to ensure that the SVC is will be safe in abnormal condition. Protection scheme of MAHADIYA substation were studied and simulated.

المستخلص

تم في هذا المشروع دراسة مخطط الحماية للمعوضات الساكنة للقدرة الراجعة لمحطة المهدية بأمدرمان .االستقرار في أنظمة القدرة يعتبر من أهم المعايير ولذلك تعتبر المعوضات الساكنة للقدرة الراجعة من أهم األجهزة التي تساعد في الحفاظ على ذلك االستقرار ويعزى ذلك إلستجابتها السريعة وقدرتها العالية كما أنها تلعب دوراً أساسياً في تقويم الجهد.

لذلك كان البد لنا من التاكد أن هذة المعوضات تعمل بالصورة المطلوبة تحت الظروف الطبيعية لنتمكن من تزيود المستهلك بالقدرة الكهربائية المطلوبة وبكفاءة عالية. حتى في حالة األعطال البد من توافر الصيانة الفورية لكي ال يحدث خلل في اإلمداد

تم دراسة المباديء األساسية للحماية كما تم ذكر خلفية تاريخية عن تعويض القدرة الراجعة للتمهيد لدراسة حماية هذة المعوضات . كما تم جمع البيانات المطلوبة من محطة المهدية وإجراء الحسابات المطلوبة لمرحالت الحماية لدراسة مخطط الحماية لهذة المعوضات.

تم محاكاة هذا المخطط بإستخدام برنامج إيتاب وأجريت العديد من السيناريوهات لحاالت غير طبيعية كحقن خطأ ثالثي األطوار لتحليل سلوك المرحالت وقواطع الدارات.

الزمن الذي يستغرقة المرحل لقطع التيار الكهربي بإستخدام قواطع الدارات وجد مناسبا ً لكي تظل هذة المعوضات أمنة وسليمة في حالة الظروف غير الطبيعية.

تم دراسة ومحاكاة مخطط الحماية لهذة المعوضات بمحطة المهدية.

Table of contents

DECLARATION OF ORGINALITY...... ii

ACKNOWLEDGEMENT ...... iii

Abstract ...... iv

v ...... المستخلص

Table of contents ...... vi

List of figures ...... ix

List of tables ...... xi

List of abbreviation and terminologies ...... xii

CHAPTER ONE: Introduction ...... 1

1.1 Overview ...... 1

1.2 Problem Statement ...... 1

1.3 Objectives ...... 1

1.4 Methodology ...... 1

1.5 Thesis Layout ...... 1

CHAPTER TWO: Literature Review ...... 3

2.1 Reactive power compensation: ...... 3 2.1.1 Principles of the Series Controllers ...... 3 2.1.2 Principles of the Shunt Controllers ...... 3 2.1.3 Principles of the Combined Series-Series Controllers ...... 4 2.1.4 Principles of Combined Series-Shunt Controllers ...... 4

2.2 Flexible AC Transmission Systems ...... 4 2.2.1 Definition of FACTS ...... 4 2.2.2 FACTS Categories ...... 5

2.3 Static VAR Compensator (SVC): ...... 6

2.3.1 Types of SVC ...... 6

2.4 SVC Common used elements: ...... 7 2.4.1 Thyristor-controlled reactor (TCR) ...... 7 2.4.2 Thyristor-switched capacitor (TSC):...... 12 2.4.3 Mechanically switched capacitor (MSC): ...... 14

2.5 Application of static VAR compensators: ...... 15

2.6 Protection of power system: ...... 15 2.6.1 Protection Equipment: ...... 16

2.7 SVC protection: ...... 18 2.7.1 Transformer and Bus-Bar Protection: ...... 18 2.7.2 TCR Protection ...... 21 2.7.3 TSC Protection ...... 22 2.7.4 Harmonic Filter Protection ...... 22 2.7.5 Auxiliary Transformer Protection ...... 23 2.7.6 Ground Fault Detection ...... 24 2.7.7 Protective Control Features in SVC control system ...... 25

CHAPTER THREE: Methodology ...... 27

3.1 Introduction: ...... 27

3.2 MAHADIYA substationoverview: ...... 28

3.3 Power transformer protection: ...... 30 3.3.1 Differential protect relay (PCS 9671) settings: ...... 30 3.3.2 Backup protection relay settings 110 kV sideover current (PCS-9611) ...... 32 3.3.3 Back up protection relay settings 33 kV side over current (PCS-9611) ...... 33

3.4 Auxiliary transformer protection: ...... 35 3.4.1 Over current PCS-9611 relay ...... 35

3.5 TCR branch: ...... 36 3.5.1 Parameters of TCR branch: ...... 36 3.5.2 setting calculations ...... 36

3.6 FC5 branch ...... 37 3.6.1 Parameters of FC5 branch ...... 37 3.6.2 setting calculations ...... 38

3.7 FC7 branch ...... 39 vii

3.7.1 Parameters of FC7 branch ...... 39 3.7.2 setting calculations ...... 40

CHAPTER FOUR: Simulation and Results ...... 42

4.1 Introduction ...... 42

4.2 ETAP simulation circuit ...... 42

4.3 Over current relays coordination ...... 43

4.4 Auxiliary transformer protection ...... 44

4.5 TCR branch protection ...... 46

4.6 FC5 branch protection ...... 47

4.7 FC7 branch protection ...... 49

4.8 Power transformer protection ...... 51

CHAPTER FIVE: Conclusion and future work ...... 53

5.1 conclusion ...... 53

5.2 Recommendations and future work...... 53

References ...... 55

Appendix A...... 56

viii

List of figures

Figure 2. 1 Overview of major FACTS-Devices ...... 5 Figure 2. 2 Thyristor-controlled reactor ...... 8 Figure 2. 3 Fundamental voltage-current characteristic of TCR ...... 10 Figure 2. 4 Three-phase TCR arrangement ...... 11 Figure 2. 5 Thyristor-switched capacitor (TSC) ...... 12 Figure 2. 6 Switch operation of a TSC ...... 13 Figure 2. 7 TSC Scheme ...... 13 Figure 2. 8 V/I characteristics of a TSC and power system ...... 14 Figure 2. 9 Electromagnetic voltage transformer ...... 18 Figure 2. 10 Typical arrangements for transformer and SVC bus (left), TCR/TSR (middle) and TSC ...... 20 Figure 2. 11 Unbalance current measured in double Y-Y filter capacitor bank ...... 23

Figure 3. 1 SVC protection configuration diagram ...... 29 Figure 3. 2 principle pf operation for differential protection ...... 30 Figure 3. 3 Differential relay characteristic ...... 31

Figure 4. 1 SVC simulated circuit single line diagram 43 Figure 4. 2 over current relays coordination 44 Figure 4. 3 three phase internal fault in auxiliary transformer 45 Figure 4. 4 sequence of operation for three phase fault in the auxiliary transformer 45 Figure 4. 5 three phase internal fault in the TCR branch 46 Figure 4. 6 sequence of operation for three-phase fault in the TCR branch 47 Figure 4. 7 three phase internal fault in the FC5 branch 47 Figure 4. 8 sequence of operation for three-phase fault in the FC5 branch 48 Figure 4. 9 Earth fault in the FC5 branch 48 Figure 4. 10 Sequence of operation for earth fault in FC5 branch 48 Figure 4. 11 three phase internal fault in the FC7 branch 49

Figure 4. 12 sequence of operation for three-phase fault in the FC7 branch 50 Figure 4. 13 Earth fault in the FC7 branch 50 Figure 4. 14 Sequence of operation for earth fault in FC7 branch 50 Figure 4. 15 Three phase internal fault in power transformer 51 Figure 4. 16 sequence of operation for three-phase fault in the power transformer 51 Figure 4. 17 Earth fault in the secondary side of the power transformer 52 Figure 4. 18 Sequence of operation for earth fault in the secondary side the power transformer 52

Figure A. 1 Differential relay setting ...... 56 Figure A. 2 Over-current relay in the 110-kV side stage one setting ...... 56 Figure A. 3 Over-current relay in the 110-kV side stage two setting ...... 57 Figure A. 4 Over-current relay in the 110-kV side stage three setting ...... 57 Figure A. 5 Over–current relay stage one setting for auxiliary transformer ...... 58 Figure A. 6 Over-current relay stage one setting for TCR branch...... 58 Figure A. 7 Over-current relay stage one setting for FC5 branch ...... 58 Figure A. 8 Thermal relay setting for the FC5 branch ...... 58 Figure A. 9 Voltage relay setting for the FC5 branch ...... 59 Figure A. 10 Unbalance current protection setting for the FC5 branch ...... 59 Figure A. 11 Over-current relay stage one setting for the FC7 branch...... 59 Figure A. 12 Thermal relay setting for the FC7 branch ...... 60 Figure A. 13 Voltage relay setting for the FC7 branch ...... 60 Figure A. 14 Unbalance current protection for the FC7 branch ...... 60

List of tables

Table 3. 1 differential protected relay (PCS 9671) data ...... 30 Table 3. 2 The basic parameters of TCR branch ...... 36 Table 3. 3 Protection CT and PT ratio ...... 36 Table 3. 4 The basic parameters of FC5 branch ...... 37 Table 3. 5 Protection CT and PT ratio ...... 38 Table 3. 6 The basic parameters of FC7 branch ...... 39 Table 3. 7 Protection CT and PT ratio ...... 40

List of abbreviation and terminologies

AC alterative current

DC direct current

CB circuit breaker

CT current transformer

DC direct current

ETAP electrical transient analysis program

GIS gas isolation station

FC5 filter capacitors for the 5th harmonics

FC7 filter capacitors for the 7th harmonics

LV low voltage

MV medium voltage

VT voltage transformer

SVC static VAR compensator

TCR thyristor control reactor

퐼푛푇푅퐴퐹푂 rated current of power transformer

푄푡푐푟 reactive power supplied by the thyristor control reactor

th 푄퐹퐶5 reactive power supplied by the 5 harmonics filter

th 푄퐹퐶7 reactive power supplied by the 7 harmonics filter

퐼퐵 based current for thermal protection

xii

Chapter one Introduction

CHAPTER ONE: Introduction

1.1 Overview

This chapter will provide the problem that need to be solved, some of the theories related to solve this problem, objectives that must be done, how these objectives are achieved and the structure of each chapter in this report.

1.2 Problem Statement

Static VAR compensators have been widely used in power systems grid because of its fast response to system changes such as voltage and reactive power variation. The protection scheme of the SVC takes significant part when installing SVCs to the power system to insure continuity and reliability of operation which lead to less economic cost. The protection scheme of SVC is provided in this project using different types of protection equipment.

1.3 Objectives

The objective of this project is to study the protection of each element in the structure of the SVC and the behavior of protection system in case of an up normal condition.

1.4 Methodology MAHADIYA substation SVC has been taken as a case study in this project. Different types of protection relays have been used with its different setting calculations to achieve the protection scheme. ETAP software has been used to simulated SVC protection scheme and study the behavior of each element of the SVC structure.

1.5 Thesis Layout The structure of this thesis is organized as follow:

Chapter 2: provide an overview of common SVC types with a background of power system protection and common used methods of protection in the SVC.

Chapter one Introduction

Chapter 3: contain an overview of MAHADIYA substation SVC and all the data and calculation related to the protection system.

Chapter 4: contain ETAP simulation circuit with all the different scenarios made to study the behavior of the protection system.

Chapter 5: provide the conclusion and the recommendations.

Chapter two Literature review

CHAPTER TWO: Literature Review

2.1 Reactive power compensation:

In power transmission, reactive power plays an important role. Real power accomplices the useful work while reactive power supports the voltage that must be controlled for system reliability. Reactive power has a profound effect on the security of power systems because it affects voltages throughout the system. Decreasing reactive power causing voltage to fall while increasing it causing voltage to rise. Voltage collapse may be occurring when the system tries to serve much more load than the voltage can support. Voltage control and reactive power management are the two aspects of a single activity that both supports reliability and facilitates commercial transactions across transmission networks. Voltage is controlled by absorbing and generating reactive power. Thus, reactive power is essential to maintain the voltage to deliver active power through transmission lines.

Different reactive power compensation methods are discussed next.

2.1.1 Principles of the Series Controllers If the line voltage is in phase quadrature with the line current, the series controller absorbs or produces reactive power, if it is not, the controllers absorbs or produces real and reactive power. Examples of such controllers are Static Synchronous Series Compensator (SSSC), Thyristor- Switched Series Capacitor (TSSC), Thyristor-Controlled Series Reactor (TCSR), to cite a few. They can be effectively used to control current and power flow in the system and to damp system’s oscillations. Among these Static Synchronous Series Compensator(SSSC) is one of the important series FACTS devices. SSSC is a solid-state voltage source inverter, injects an almost sinusoidal voltage, of variable magnitude in series with the transmission line. The injected voltage is almost in quadrature with the line current. A small part of the injected voltage, which in phase with the line current, provides the losses in the inverter.

2.1.2 Principles of the Shunt Controllers Shunt controllers are similar to the series controllers with the difference being that they inject current into the system at the point where they are connected. Variable shunt impedance

Chapter two Literature review connected to a line causes variable current flow by injecting a current into the system. If the injected current is in phase quadrature with the line voltage, the controller adjusts reactive power while if the current is not in phase quadrature, the controller adjusts real power. Examples of such systems are Static Synchronous Generator (SSG), Static Var Compensator (SVC).

2.1.3 Principles of the Combined Series-Series Controllers A combined series-series controller may have two configurations. One configuration consists of series controllers operating in a coordinated manner in multiline transmission system. The other configuration provides independent reactive power control for each line of a multiline transmission system and, at the same time, facilitates real power transfer through the power link. An example of this type of controller is the Interline Power Flow Controller (IPFC), which helps in balancing both the real and reactive power flows on the lines.

2.1.4 Principles of Combined Series-Shunt Controllers A combined series-shunt controller may have two configurations, one being two separate series and shunt controllers that operate in a coordinated manner and the other one being interconnected series and shunt components. In each configuration, the shunt component injects a current into the system while the series component injects a series voltage. When these two elements are unified, real power can be exchanged between them via the power link. Examples of such controllers are UPFC (Unified Power Flow Controller) and Thyristor-Controlled Phase- Shifting Transformer (TCPST). These make use of the advantages of both series and shunt controllers and, hence, facilitate effective and independent power/current flow and line voltage control. [1]

2.2 Flexible AC Transmission Systems

2.2.1 Definition of FACTS According to IEEE, FACTS, which is the abbreviation of Flexible AC Transmission Systems, is defined as follows:

“Alternating current transmission systems incorporating power electronics based and other static controllers to enhance controllability and APTC”.

Chapter two Literature review

Since the ʺother static controllersʺ based FACTS devices are not widely used in current PSs, the focused only on the power electronics based FACTS devices. The FACTS controllers are classified as follows:

• Thyristor controlled based FACTS controllers such as TSC, TCR, FC‐TCR, SVC, TCSC, TCPAR etc. • VSI based FACTS controllers such as SSSC, STATCOM, UPFC, GUPFC, IPFC, GIPFC, HPFC etc.

Figure 2. 1 Overview of major FACTS-Devices

2.2.2 FACTS Categories In general, FACTS devices can be divided into four categories:

2.2.2.1 Series Connected ‐FACTS Devices: Series FACTS devices could be variable impedance, such as capacitor, reactor, etc., or power electronics based variable source of main frequency, sub synchronous and harmonic frequencies (or a combination) to serve the desired need. In principle, all series FACTS devices inject voltage in series with the transmission line.

Chapter two Literature review

2.2.2.2 Shunt Connected ‐FACTS Devices: Shunt FACTS devices may be variable impedance, variable source, or a combination of these. They inject current into the system at the point of connection

2.2.2.3 Combined Series‐series Connected ‐FACTS Device: Combined series‐series FACTS device is a combination of separate series FACTS devices, which are controlled in a coordinated manner.

2.2.2.4 Combined Series‐shunt Connected ‐FACTS Device: Combined series‐shunt FACTS device is a combination of separate shunt and series devices, which are controlled in a coordinated manner or one device with series and shunt elements. [2]

2.3 Static VAR Compensator (SVC):

The SVC (Static Var Compensator) is a member of the FACTS (Flexible AC Transmission System) family. By means of thyristor control of reactive power, it enables dynamic voltage control at the point of common connection with a grid. The fast response of an SVC makes it highly suitable for fulfilling functions such as steady-state as well as dynamic voltage stabilization, meaning power transfer capability increases, reduced voltage variations, and flicker reduction at industrial arc furnaces. SVCs are special in the sense that they are needed the most during network disturbances. At these occasions, they may make the difference between a network collapse and successful continued operation. It is therefore, imperative that they do not trip when they are needed the most.

2.3.1 Types of SVC

The following are the basic types of reactive power control elements which make up all or part of any static var system:

• Saturated reactor (SR) • Thyristor-controlled reactor (TCR) • Thyristor-switched capacitor (TSC) • Thyristor-switched reactor (TSR)

Chapter two Literature review

• Thyristor-controlled transformer (TCT) • Self- or line-commutated converter (SCC/LCC)

2.4 SVC Common used elements:

In general, the elements of an SVS operate on the principle of adjustable susceptance. The controlled susceptance is either a reactor or a capacitor. We will discuss next the operation of the more commonly used elements: TCR, TSC, and MSC.

2.4.1 Thyristor-controlled reactor (TCR)

Principle of operation:

The basic elements of a TCR are a reactor in series with a bidirectional thyristor switch as shown in Figure 2. 2 (a)

The thyristors conduct on alternate half-cycles of the supply frequency depending on the firing angle a, which is measured from a zero crossing of voltage. Full conduction is obtained with a firing angle of 90°. The current is essentially reactive and sinusoidal. Partial conduction is obtained with firing angles between 90° and 180°, as shown in Figure 2. 2 (b). Firing angles between 0 and 90° are not allowed as they produce asymmetrical currents with a dc component.

Let σ be the conduction angle, related to α by

휎 = 2(휋 − 훼)

The instantaneous current ⅈis given by

√2푉 (cos 훼 − cos 휔푡) 푓표푟 훼 < 휔푡 < 훼 + 휎 ⅈ = { 푋퐿 0 푓표푟 훼 + 휎 < 휔푡 < 훼 + 휋

Fourier analysis of the current waveform gives the fundamental component: 7

Chapter two Literature review

푉 휎 − sin 휎 퐼1 = 푋퐿 휋

I1and V are RMS values, and XL is the reactance of the reactor at fundamental frequency.

The effect of increasing α (i.e., decreasing σ) is to reduce the fundamental component I1. This is equivalent to increasing the effective inductance of the reactor.

In effect, so far as the fundamental frequency current component is concerned, the TCR is a controllable susceptance. The effective susceptance as a function of the firing angle α is

Figure 2. 2 Thyristor-controlled reactor

Chapter two Literature review

퐼 휎 − sin 휎 퐵(훼) = 1 = 푉 휋푋퐿

(2휋 − 훼) + sin 2훼 = 휋푋퐿

The maximum value of the effective susceptance is at full conduction (α = 90°, σ

=180°), and is equal to 1/XL; the minimum value is zero, obtained with α =180° or σ=0°.

This susceptance control principle is known as phase control. The susceptance is switched into the system for a controllable fraction of every half cycle. The variation in susceptance as well as the TCR current is smooth or continuous.

The TCR requires a control system which determines the firing instants (i.e., firing angle α) measured from the last zero crossing of the voltage (synchronization of firing angles). In some designs, the control system responds to a signal that directly represents the desired susceptance. In others, the control responds to error signals such as voltage deviation, auxiliary stabilizing signals, etc. The result is a steady-state V/I characteristic shown in Figure 2.4, which can be described by

V = Vref+XSLI1

where XSL is the slope reactance determined by the control system gain.

The TCR voltage control characteristic can be extended into the capacitive region by adding in parallel a fixed capacitor bank or switched capacitor banks

Chapter two Literature review

Figure 2. 3 Fundamental voltage-current characteristic of TCR Harmonics:

As α is increased from 90° to 180°, the current waveform becomes less and less sinusoidal; in other words, the TCR generates harmonics. For the single-phase device considered so far, if the firing of the thyristors is symmetrical (equal for both thyristors), only odd harmonics are generated. For a three-phase system, the preferred arrangement is to have the three single-phase TCR elements connected in delta (6-pulse TCR) as shown in Figure 2. 4(a). For balanced conditions, all triple (3, 9, ...) harmonics circulate within the closed delta and are therefore absent from the line currents. Filters are often used to remove harmonic currents.

Chapter two Literature review

Figure 2. 4 Three-phase TCR arrangement Elimination of 5th and 7th harmonics can be achieved by using two 6-pulse TCRs of equal rating, fed from two secondary windings of the step-down transformers, one connected in Y and the other in Δ as shown in Figure 2. 4(b). Since the voltages applied to the TCRs have a phase difference of 30°, 5th and 7thharmonics are eliminated from the primary-side line current. This is known as a 12-pulse arrangement because there are 12 thyristor firings every cycle of the three-phase line voltage. With the 12-pulse scheme, the lowest-order characteristic harmonics are the 11th and 13th. These can be filtered with a simple capacitor bank.

Dynamic response:

The TCR responds in about 5 to 10ms, but delays are introduced by measurement and control circuits. To ensure control loop stability the response rate may have to be limited. For these reasons response times are typically around 1 to 5 cycles of supply frequency.

Chapter two Literature review

2.4.2 Thyristor-switched capacitor (TSC):

Principle of operation:

A thyristor-switched capacitor scheme consists of a capacitor bank split up into appropriately sized units, each of which is switched on and off by using thyristor switches. Each single-phase unit consists of a capacitor (C) in series with a bidirectional thyristor switch and a small inductor (L) as shown in Figure 2. 5(a). The purpose of the inductor is to limit switching transients, to damp inrush currents, and to prevent resonance with the network. In three-phase applications, the basic units are connected in A as shown in Figure 2. 5(b).

Figure 2. 5 Thyristor-switched capacitor (TSC) The switching of capacitors excites transients which may be large or small depending on the resonant frequency of the capacitors with the external system. The thyristor firing controls are designed to minimize the switching transients. This is achieved by choosing the switching instant when the voltage across the thyristor switch is at a minimum, ideally zero. Figure 2. 6 illustrates the operating principle. The switching-on instant (t1) is chosen so that the bus voltage V is at its maximum and of the same polarity as the capacitor voltage; this ensures a transient-free switching. The switching- off instant (t2) corresponds to a current zero. The capacitor will then remain charged to a peak voltage, either positive or negative, ready for the next switch-on operation.

Chapter two Literature review

Figure 2. 6 Switch operation of a TSC The susceptance control principle used by a TSC is known as the integral cycle control; the susceptance is switched in for an integral number of exact half cycles. The susceptance is divided into several parallel units, and the susceptance is varied by controlling the number of units in conduction. A change can be made every half cycle. This form of control does not generate harmonics. Figure 2. 7 shows the basic scheme of a TSC consisting of parallel Δ connected TSC elements and a controller. When the bus voltage deviates from the reference value (푉푟푒푓) beyond the dead band in either direction, the control switches in (or out) one or more capacitor banks until the voltage returns inside the dead band, provided that not all the banks have been switched in (or out).

Figure 2. 7 TSC Scheme

Chapter two Literature review

Dynamic response:

The V/I characteristic of a TSC compensator is shown in Figure 2. 8. We see that the voltage control provided is discontinuous or stepwise. It is determined by the rating and number of parallel connected units. In high voltage applications, the number of shunt capacitor banks is limited because of the high cost of thyristors. The power system V/I characteristics, as system conditions change, intersect the TSC V/I characteristics at discrete points. The bus voltage V is controlled within the range푉푟푒푓 ± 퐷푉/2, where DV is the dead band. When the system is operating so that its

Figure 2. 8 V/I characteristics of a TSC and power system characteristic is represented by line S1, then capacitor C1 will be switched in and operating point A prevails. If the system characteristic suddenly changes to S2, the bus voltage drops initially to a value represented by operating point B. The TSC control switches in bank C2 to change the operating point to C, bringing the voltage within the desired range. Thus, the compensator current can change in discrete steps. The time taken for executing a command from the controller ranges from one-half cycle to one cycle.

2.4.3 Mechanically switched capacitor (MSC):

Typically, an MSC scheme consists of one or more capacitor units connected to the power system by a circuit-breaker. A small reactor might be connected in series with the capacitor to

Chapter two Literature review damp energizing transients and reduce harmonics. Prestrike and restrike-free circuit-breakers have to be used to avoid system overvoltage’s due to capacitor-switching transients.

The V/I characteristic is linear and similar to that of a TSC.

2.5 Application of static VAR compensators:

Since their first application in the late 1970s, the use of SVCs in transmission systems has been increasing steadily. By virtue of their ability to provide continuous and rapid control of reactive power and voltage, SVCs can enhance several aspects of transmission system performance. Applications to date include the following:

• Control of temporary (power frequency) overvoltage’s • Prevention of voltage collapse • Enhancement of transient stability • Enhancement of damping of system oscillations. At the sub transmission and distribution system levels, SVCs are used for balancing the three phases of systems supplying unbalanced loads. They are also used to minimize fluctuations in supply voltage caused by repetitive-impact loads such as dragline loads of mining plants, rolling mills, and arc furnaces. [3]

2.6 Protection of power system: The purpose of an electrical power system is to generate and supply electrical energy to consumers. The system should be designed and managed to deliver this energy to the utilization points with both reliability and economy Severe disruption to the normal routine of modern society is likely if power outages are frequent or prolonged, placing an increasing emphasis on reliability and security of supply as the requirements of reliability and economy are largely opposed, power system design is inevitably a compromise.

Many items of equipment are very expensive to maximize the return on this outlay; the system must be utilized as much as possible within the applicable constraints of security and reliability of supply. No matter how well designed, faults will always occur on a power system, and these faults may represent a risk to life and/or property.

Chapter two Literature review

2.6.1 Protection Equipment: In order to fulfil the requirements of protection with the optimum speed for the many different configurations, operating conditions and construction features of power systems, it has been necessary to develop many types of relay that respond to various functions of the power system quantities.

2.6.1.1 Relays: Relays frequently measure complex functions of the system quantities, which are only readily expressible by mathematical or graphical means.

Relays may be classified according to the technology used: a. electromechanical b. static c. digital d. numerical The different types have somewhat different capabilities, due to the limitations of the technology used

A. Electromechanical: They work on the principle of a mechanical force causing operation of a relay contact in response to a stimulus the mechanical force is generated through current flow in one or more windings on a magnetic core or cores, hence the term electromechanical relay the principle advantage of such relays is that they provide galvanic isolation between the inputs and outputs in a simple, cheap and reliable form – therefore for simple on/off switching functions where the output contacts have to carry substantial currents, they are still used.

B. Static: Their design is based on the use of analogue electronic devices instead of coils and magnets to create the relay characteristic. Early versions used discrete devices such as transistors and diodes in conjunction with resistors, capacitors, inductors, etc., but advances in electronics enabled the use of linear and digital integrated circuits in later versions for signal processing and implementation of logic functions.

Chapter two Literature review

C. Digital: Digital relays introduce A/D conversion of all measured analogue quantities and use a microprocessor to implement the protection algorithm. The microprocessor may use some kind of counting technique, or use the Discrete Fourier Transform (DFT) to implement the algorithm.

D. Numerical: Typically, they use a specialized digital signal processor (DSP) as the computational hardware, together with the associated software tools.

The input analogue signals are converted into a digital representation and processed according to the appropriate mathematical algorithm. [4]

2.6.1.2 Fuses: Probably the oldest, simplest, cheapest, and most-often used type of protection device is the fuse. The operation of a fuse is very straightforward: The thermal energy of the excessive current causes the fuse-element to melt and the current path is interrupted. Technological developments have made fuses more predictable, faster, and safer (not to explode).

A common misconception about a fuse is that it will blow as soon as the current exceeds Its rated value (i.e. the value stamped on the cartridge). This is far from the truth.

2.6.1.3 Current Transformers: All current transformers used in protection are basically similar in construction to Standard transformers in that they consist of magnetically coupled primary and secondary Windings, wound on a common iron core, the primary winding being connected in series with the network unlike voltage transformers. They must therefore withstand the networks short-circuit current.

2.6.1.4 Voltage Transformers: There are basically, two types of voltage transformers used for protection equipment.

1. Electromagnetic type (commonly referred to as a VT) 2. Capacitor type (referred to as a CVT). The electromagnetic type is a step-down transformer whose primary (HV) and secondary (LV) windings are connected as below

Chapter two Literature review

Figure 2. 9 Electromagnetic voltage transformer The number of turns in a winding is directly proportional to the open-circuit voltage being measured or produced across it. The above diagram is a single-phase VT. In the three-phase system it is necessary to use three VTs at one per phase and they being connected in star or delta depending on the method of connection of the main power source being monitored. This type of electromagnetic transformers is used in voltage circuits up to 110/132 kV.

2.6.1.5 Circuit breakers: Where fuses are unsuitable or inadequate, protective relays and circuit breakers are us in combination to detect and isolate faults. Circuit breakers are the main making and breaking devices in an electrical circuit to allow or disallow flow of power from source to the load. These carry the load currents continuously and are expected to be switched ON with loads (making capacity). These should also be capable of breaking a live circuit under normal switching OFF conditions as well as under fault conditions carrying the expected fault current until completely isolating the fault side (rupturing/breaking capacity). [5]France

2.7 SVC protection:

Security is the number one requirement on SVC protections, given reasonable dependability is maintained. The way to achieve high security is to minimize the number of relays and protective functions used in a plant.

2.7.1 Transformer and Bus-Bar Protection: Utility SVCs normally make use of a power transformer between the power grid and the SVC medium voltage (MV) bus bar. On this bus harmonic filter, thyristor controlled reactors and capacitors are connected. In many cases, an auxiliary power transformer is also connected to this bus. It is important to note that the power transformer is the only connection of this bus to the mains. There are never several in feeds or more than one power transformer in the circuit.

Chapter two Literature review

SVC transformers are, like generator transformers, made with a large turn ratio. The voltage on theSVC MV bus is typically in the span of 15-30 kV irrespective of the voltage level on the mains. A very normal transformer turn ratio is 400/25 kV. This large ratio results in very high short circuit currents on the MV bus, it is frequently in the range of 50-90 kA (RMS symmetrical). The transformer current in its MV bushings also become large due to large power and low voltage, 5-15 kA are normal values. The large fault and load current currents must be considered when designing the protection system.

High load currents (>10 kA depending on transformer brand) makes it impossible to use the concept of bushings connected directly on the transformer tank, instead special high current hoods have to be uses.

These hoods are of non-magnetic material. They are quite narrow and cannot fit current transformers(CTs). Instead external current transformers have to be used. The high short circuit current excludes post type CTs leaving bushing type CTs as the only choice. The largest current ratings available is8000 A, therefore two CTs have to be connected in parallel in many cases. Considering the fact, the connection of the SVC MV bus bar to the mains is made by one single power transformer and the very large load current makes it reasonable to leave the standard protection concept with a differential current relay connected directly across the power transformer. The better design is to extend the protection zone to also include the SVC MV bus bar. In this design, the CTs in all the other SVC branches are used to close the differential zone.

Standard transformer protective functions shall be used, differential current, restricted earth fault current and over current functions are recommended.

When it comes to overvoltage protection, it is important to note that SVC transformers are made with large magnetic cores. The saturation voltage is typically as high as 120-125% of nominal voltage. This figure is derived from the large voltage variation on the SVC MV bus. The transformer impedance is normally close to 15% on its power rating. As the current through the transformer is purely reactive (inductive or capacitive) the voltage on the MV bus will vary +/- 15% when the SVC goes from fully capacitive to fully inductive operation.

Typically, the voltage reference for the SVC controller is settable between 100% and 110% voltage on the mains. Totally the voltage on the MV bus will vary from +25% to -15%. The

Chapter two Literature review power transformer must be designed not to saturate at maximum continuous voltage on this bus. Over excitation of a transformer can damage the transformer if it persists. Overexcitation results in excessive core flux resulting in high interlamination core voltage, which may result in iron burning at high flux levels, the transformer saturates since flux begins to flow in leakage paths not designed to carry it, again causing damage. The normal power transformer design is to have the winding with the lowest voltage closest to the core. For an SVC, it is the winding connected to MV bus. This winding determines the magnetization of the core, one can therefore say that an SVC transformer is magnetized from the SVC MV bus! Over excitation relays, if used, shall be connected to the MV bus, it is almost impossible to saturate an SVC power transformer from the high voltage side. The protection is not used as standard protection since overvoltage protection on secondary side will prevent high voltage resulting in over flux. Customer usually specifies what kind of transformer guards he requires in his protections solution. Commonly used transformer guards are; Buchholz function, sudden pressure function, high oil temperature, high winding temperature, low oil level.

Figure 2. 10 Typical arrangements for transformer and SVC bus (left), TCR/TSR (middle) and TSC

(right) differential zones.

Chapter two Literature review

2.7.2 TCR Protection A TCR or TSR branch is delta connected where each phase consists of a thyristor valve and two reactor stacks. The thyristor valve is electrically located between the reactors. By combining one-line Current Transformer (CT) with two branch CTs, a protective zone encompassing two reactor halves and a thyristor valve is created in a main differential protection. By permutation, three such zones are aggregated in the TCR to provide detection and clearance of inter-zone faults. Time delayed Over current relays, with an added instantaneous step sensing the branch currents are generally used as back-up. The reactors are protected by thermal overload relays. The split arrangement of the reactors in each phase provides extra protection to the thyristors in event of a reactor fault, i.e. fault current is limited and the risk for steep front voltage surges eliminated. The valves are also protected against thermal overload by a specific function (TCR current limiter) in the SVC control system.

Differential protection can be of high or low impedance type. The protection serves as the main protection for short circuits between the different protective zones. The protection is unaffected by SVC energization and any valve misfiring. Differential protection of low impedance type will have higher requirements on CT’s compared to high impedance types. Low impedance types of differential protection need to be blocked during SVC energization, if energization is performed with fully conducting TCR valves. Large DC components, with long time constant will be present in the TCR current at full conduction. Due to the large DC component and very long primary time constant false differential current exists. Restraint criteria are generally not fulfilled and will not stabilize the protection.

Unsymmetrical TCR operation and turn to turn faults can also be detected by a negative phase sequence protection. However, turn to turn faults are extremely difficult to detect. The small unbalances and sequence currents associated with turn to turn faults generally are smaller than the existing tolerable unbalances in the system, i.e. unbalances due to negative sequence, component tolerances, etc. Consequently, there seems to be no reliable handle to distinguish between the intolerable and tolerable conditions. As the turn to turn fault spreads to more turn, the current will increase. Negative sequence relays must consider conditions mentioned above, the settings are generally high which makes the relay insensitive. The relay should be time delayed to avoid operation on system transients and external faults.

Chapter two Literature review

The valves are also protected against thermal overload by a specific function (TCR current limiter) in the SVC control system. The selective protection simulates the temperature inside the reactor and works with the time constant of the reactors. For some installations this protection is installed in the SVC control system. Experience from hundreds of SVC’s has also shown that it is very rare that this protection operates since the TCR current will be limited by protective control features implemented in highly reliable SVC control systems.

2.7.3 TSC Protection A TSC is delta connected where each phase consists of a thyristor valve, a reactor and a capacitor bank. The thyristor valve is electrically located between the reactor and the capacitor. The capacitor bank is generally divided into two parallel halves with a number of capacitor units connected in series and parallel. The differential protection scheme is described in (TCR protection). An Over current relay sensing the line currents in the TSC provides backup. Unbalance protection function supervises the voltage across capacitor by measuring unbalance current. Unbalance current can be measured in different configurations as indicated in Figure 2. 10. Two overvoltage criterions are used: One overvoltage criterion for the unit and one criterion for internal elements. In case of excessive capacitor voltage, an alarm or a trip command is issued.

2.7.4 Harmonic Filter Protection For most SVC installations harmonic filters are connected. Harmonic filters perform the dual task of providing reactive power generation at fundamental (grid) frequency and performing the harmonic filtering needed to take care of the harmonics generated by the TCR. Filter banks for SVC applications are generally divided into two parallel banks in Y-Y connection with ungrounded neutrals tied together. Internal fuses protect the capacitor units.

Differential protections are not to be preferred in harmonics filter since complicate bus arrangement will apply. Harmonics filters are generally ungrounded and double wye connected. This means that the two strings in the capacitor bank is tied together internally in the capacitor bank, see figure below. Differential protections for filter banks will require CT’s with high current rating in the neutral.

Chapter two Literature review

Harmonics generated by the system and the TCR are important when designing small capacitor banks and shall be considered in rating calculations as well as for the protection of the capacitors. Overload protection functions shall supervise the voltage across capacitors by measuring branch currents and calculation the resulting capacitor voltage, including the effects of harmonic frequencies. Relays that are designed to operate for fundamental component shall not be used.

Unbalance protection function supervises the voltage across capacitor by measuring unbalance current.

Unbalance current can be measured in different configurations as indicated in Figure 2. 11. Two overvoltage criterions are used: One overvoltage criterion for the unit and one criterion for internal elements. In case of excessive capacitor voltage, an alarm or a trip command is issued.

Figure 2. 11 Unbalance current measured in double Y-Y filter capacitor bank 2.7.5 Auxiliary Transformer Protection It is quite common to use the SVC MV bus for one source of auxiliary power to the SVC. The high short circuit power on the bus makes it difficult to trip the aux power transformer in case of a fault, no fuses nor would circuit breakers do. Fuses are for maximum 40 kA short circuit power and circuit breakers for maximum 63 kA. Tripping the complete plant to disconnect the aux power is bad for the forced outage availability. The best way to overcome the difficulties is to

Chapter two Literature review install a series reactor in front of the aux power transformer. It should be designed to bring down the fault current below 40 kA.

Current limiting fuses are the fastest and best means to minimize damage to the aux power transformer. In order to be able to replace the fuses or to avoid unsymmetrical operation after a fault disconnector is also needed.

The aux power transformer shall be protected by means of over current relays, tripping the complete plant in case the fuse operation fails. Load current is very low, typically in the range of 10 A. A protection scheme is needed to detect current slightly above the max load for overload purpose and at the same time being able to detect short circuit current in the range of 40 kA. This can be done by two different over current relays, one connected to a CT with a turn ratio matching the load current and a second one having a turn ratio selected for short circuit current.

2.7.6 Ground Fault Detection Ground faults within an SVC are extremely rare. Overhead lightning protection of the complete SVC yard is provided. The medium voltage (downstream the main power transformer) electrical circuit is built with relative large clearances/creepage distances. The thyristor branch circuits/equipment is fenced in. The environment is considered clean, the pollution level is low. Surge arresters are provided on the SVC medium voltage circuit. The key to avoid ground faults is to keep animals and forgotten tools out of the energized areas.

ABB has for a few customers recently proposed and delivered an alternative solution related to ground fault location within the SVC. The philosophy is to increase the reliability of the SVC by eliminating the grounding circuit. With the grounding transformer removed the ground fault has to be detected by a voltage relay sensing a zero-sequence voltage. Since the ground fault now will not be selective detected, it will instead be located by an automatic reclosing sequence. Upon SVC trip, all the branch disconnectors will be opened. The SVC breaker is then reclosed. Two scenarios are to be considered:

a) If the ground fault remains, the SVC main circuit breaker is tripped again and it is concluded that

Chapter two Literature review the ground fault is on the common SVC bus, or within the main power transformer. Filters install without disconnectors will be included in the energization sequence. The SVC is then put into lock-out condition.

b) If the ground fault remains but the SVC is not tripped, the fault has to be in one of the SVC branches. These are then closed in one-by-one, using their motor-operated disconnectors, until we get a ground fault trip again. The branch that initiates this second ground fault tripping is then isolated using its motor-operated disconnector. Finally, the SVC main circuit breaker is closed in again and the SVC resumes operation in degraded mode, if allowed. SVC operation without harmonic filters is generally, not recommended.

The above-described auto-reclose sequence will take somewhat (say one minute) longer time to complete, than a normal start sequence. It also will involve one additional (no load) transformer energization. The energizations of the thyristor branches, using their motor-operated disconnectors isnot noticeable as the thyristor valves are blocked and no “charging current” will develop. The arcing at the disconnector will be completely negligible. The additional closing in of the transformer, which could have a medium voltage ground fault, constitutes no risk for the transformer.

The traditional way to provide ground fault location within an SVC, has been to provide a medium voltage grounding transformer (z-connection). Grounding transformers are not recommended since there are concerns around the “grounding circuit” within an SVC. First there is a prospective resonance between the grounding transformer and (part of) the TSC capacitor bank. Secondly the fault current on the SVC medium voltage bus may be very high. Fuses are needed to protect the grounding transformer in case of an internal fault, but fuse selection is difficult with this combination of high fault current and relatively high voltage. Additional components are introduced and these in their turn shall be protected. This will have a negative effect on the SVC reliability and availability.

2.7.7 Protective Control Features in SVC control system Fundamental frequency current or voltage overload in any branch in the SVC is prevented by the control system. There are control functions making sure that the total SVC current i.e. the current

Chapter two Literature review through the power transformer or the current in the TCR cannot become higher than the component ratings. The voltage on the SVC MV bus is also controlled to make sure it cannot exceed its design value. DC current in the TCR is actively suppressed by a control function manipulating the thyristor firing instants. When it comes to detecting malfunctions in the plant the most important function is to compare the actual currents in thyristor controlled branches with currents simulated in the control system. The simulation is based on measured system voltage and actual firing orders to the thyristors. In case there is a deviation between the two values exceeding a limit, the plant is considered faulty. There are also a number of self- supervision functions and hardware checks making sure the control system is working properly. In case of a detected faulty control system the operation will automatically be transferred to a redundant system, in case such a system is not available the SVC will trip. [6]

Chapter three methodology

CHAPTER THREE: Methodology Case study: MAHADIYA substation SVC

3.1 Introduction:

Static Var Compensator (SVC) protection is presented in this chapter. SVC systems come in a wide number of arrangements, and are custom designed for specific applications. For SVC applications the control and protection system plays an essential role in the overall performance of the power system. From protection standpoint, an extensive protection system is generally required for SVCs to optimize the equipment operational limits for maximum utilization.

This chapter outlines the experience gained from, and design aspects of relay protection for SVC’s.

This chapter describes different relay protection principles applicable to SVCs. It also includes an overview of SVC protection methods. It covers the protection for the SVC itself, the power transformer, and the active branches, i.e. TCR, auxiliary transformer and harmonic filters are of specific interest. These branches are exposed to severe current and voltage transient during system disturbances. Insensitivity to harmonics and DC current are essential.

SVCs are normally ungrounded on the MV bus and residual voltage protection is used to detect ground faults. If selective earth fault protection is required for the SVC, this can be accomplished busing either a grounding transformer or an automatic enclosure scheme.

Special protection functions are integrated in the SVC control system to detect abnormal operating conditions and to react rapidly to avoid damage and unnecessary tripping by the plant protection system. Those protection functions and their interaction with power system is an important criterion for selection and application of each protection device are covered in the chapter.

Chapter three methodology

3.2 MAHADIYA substation overview:

Mahadiya substation is one of the few substations in Sudan that include SVC. the substation is located in Omdurman, it contains six main transformers described as follow:

• transformer one (220kv /110kv) rated 150 MVA. • transformer two and three (110kv/33kv/11kv) rated (100MVA,100MVA,40MVA) respectively. • transformer four and five (220kv/110kv/33kv) rated (150MVA,150MVA,50MVA) respectively. • transformer six is the SVC transformer .SVC is connected in secondary side of the transformer in the 33-kVbus-bar. The study was carried out in the section of the substation that contains transformer (6) which is the transformer that is connected to the SVC bus-bar. The SVC in this substation consist of three main branches connected to the 33-kV bus-bar the (TCR, FC5 and the FC7).

The capacitors of the fifth and the seventh harmonics branches used to eliminate the harmonics and supply the reactive power needed. The third harmonics is eliminated by the delta connection of the secondary windings of the power transformer.

Chapter three methodology

Figure 3. 1 SVC protection configuration diagram

Chapter three methodology

3.3 Power transformer protection:

The power transformer which is usually a (step down) transformer is placed between the high voltage busbar and the low voltage busbar to which the thyristor valves are connected. And is protected using differential protection as a primary protection and over-current protection as a secondary protection in the high voltage and the low voltage sides.

This protection was achieved by using the relay (PCS 9671)

Figure 3. 2 principle pf operation for differential protection 3.3.1 Differential protect relay (PCS 9671) settings:

3.3.1.1 Data: Table 3. 1 differential protected relay (PCS 9671) data

Rated Vector Relay CT ratio group type Voltage Power Current Power Transformer 110/33 42000/42000 220.4/734.8 YNd11 — — data kV kVA A Relay data — — 1 A — PCS — 9671 110 kV side CT data — — — — — 1000/1 A

33 kV side CT data — — — — — 1250/1 A

Chapter three methodology

3.3.1.2 Settings calculations In order to calculate pickup current for differential relay the inrush current which is usually caused by starting or recovering transformers must be taken into the account.

Figure 3. 3 Differential relay characteristic a) Pickup setting of biased differential protection

220.4 Biased pickup current= 0.3 × 퐼푛 = 0.3 × = 0.07 퐴 = 0.3 푝푢Trip two sides CBs 푇푅퐴퐹푂 1000

Where: - 퐼푛푇푅퐴퐹푂is the transformer rated current

The instantaneous pickup current must be greater than the maximum inrush current. The inrush current is always between 5~8 times the rated current in peak value, therefore:

220.4 Instant pickup current= 8 × = 1.76 퐴 = 8.0 푝푢Trip two sides CBs 1000 b) Coefficient of 2nd harmonics for inrush current detection

퐼(2 ∗ 푓0) = 15% 퐼(푓0)

퐾퐻푚2퐼푟푢푠ℎ = 0.15 c) Coefficient of 5th harmonics for overexcitation detection

퐼(5 ∗ 푓0) = 25% 퐼(푓0)

Chapter three methodology

퐾퐻푚5푂푣퐸푥푐 = 0.25

3.3.2 Backup protection relay settings 110 kV sideover current (PCS-9611)

3.3.2.1 Data Relay rated current: 1 A

• Phase CT primary : 1000 A • Phase CT secondary : 1 A

3.3.2.2 Settings calculations Over-current relay operates at three definite time stages calculated as follow a) 1st stage Definite Time Overcurrent pickup current must be set to the maximum short-circuit current for a fault on the LV side of the transformer (about 0.44kA) and the inrush current of transformer (5퐼푛푡푓):

220.4 (퐼 ≫) = 5 × = 1.1퐴 1000

The time delay is set to 0.1 sec, tripping HV side CB. b) 2st stage Definite Time Overcurrent

1.47 × 1250 × 33 (퐼 ≫) = 1.2 × = 0.66 퐴 1000 × 110

The time delays set to 0.6 sec. c) 3st stage Definite Time Overcurrent

0.65 × 1250 × 33 (퐼 ≫) = 1.2 × = 0.3 퐴 1000 × 110

The time delay is set to 2.1 sec.

Chapter three methodology

3.3.2.3 Earth fault settings In order to ensure the correct direction, zero sequence current is self-calculated.

a) 1st stage Definite Time Zero Sequence Overcurrent

1.3 × 2.0 × 480 3퐼 ≫= = 1.248 퐴 (퐶푇 푟푎푡푒 1000/1) 0 1000

3퐼0 = 1.25 퐴Direction: Point to 110kV bus-bar.

Time delay≫= 0.9 sec tripping HV side CB. b) 2st stage Definite Time Zero Sequence Overcurrent pickup current set to the maximum unbalanced current during normal operation and unbalanced zero-sequence inrush current.

220.4 3퐼 > 0.4 퐼푛 = 0.4 × = 0.09 퐴 푇푅퐴퐹푂 1000

Select 퐼0 >=0.09A Direction: Point to 110kV bus-bar.

Time delay≫=3.0 sec tripping HV side CB.

3.3.3 Back up protection relay settings 33 kV side over current (PCS-9611)

3.3.3.1 Data Relay rated current: 1 A

• Phase CT primary: 1250 A • Phase CT secondary: 1 A • Neutral CT primary: 100 A • Neutral CT secondary: 1 A

3.3.3.2 Settings calculations a) 1st stage Definite Time Overcurrent

Chapter three methodology pickup current Coordinated with the settings of 33kV TCR branch protection:

800 (퐼 ≫) = 1.1 × 2.09 × = 1.47 퐴 1250

The time delay is set to 0.3 sec. b) 2st stage Definite Time Overcurrent pickup current Coordinated with the settings of 33kV TCR branch protection, and more than the maximum load current of transformer.

1.05 (퐼 ≫) = 퐼푛 = 0.65 퐴 0.95 푇푅퐴퐹푂

The time delay is set to 1.8 sec.

3.3.3.3 Earth Fault Settings a) 1st stage Definite Time Zero Sequence Overcurrent

√3푈 퐼푁 ≫= = 2.88 퐴 푍0 × 퐾푠 × 100

Select 3퐼0 ≫= 2.88 퐴

Time delay ≫= 0.3 sec tripping LV side CB. b) 2st stage Definite Time Zero Sequence Overcurrent

734.8 퐼 >= 0.1퐼푛 = 0.1 × = 0.74 퐴 푁 푇푅퐴퐹푂 100

Select 3퐼0 >= 0.74 퐴

Time delay≫= 1.8 sec tripping LV side CB.

Chapter three methodology

3.4 Auxiliary transformer protection:

3.4.1 Over current PCS-9611 relay

3.4.1.1 Data • Relay rated current: 1 A • Phase CT primary: 100 A • Phase CT secondary: 1 A

3.4.1.2 Settings calculations a) 1st stage Definite Time Overcurrent

The pickup current setting must be greater than the maximum inrush current and the maximum short circuit current for a fault on the LV side of the auxiliary transformer (about 68A). The inrush current is always between 8～12 times the rated current in peak value, therefore:

68 (퐼 >) = 1.5 × = 1.02 퐴 100

Direction: Point to the auxiliary transformer.

The time delay (t >) is set to 0.5 sec. Trip main transformer two sides CBs. b) 2st stage Definite Time Overcurrent pickup current set to be greater than the rated current.

퐾푘 1.5 4.4 (퐼 ≫) = × 퐼푛 = × = 0.077 퐴 퐾푟 0.85 100

Select: (퐼 ≫) = 0.1 퐴

The time delay (푡 ≫) is set to 5 sec. Trip main transformer two sides CBs

Chapter three methodology

3.5 TCR branch:

3.5.1 Parameters of TCR branch: Table 3. 2 The basic parameters of TCR branch

Rated capacity 55Mvar Rated voltage 33kV Actual inductance (mH) 127.47 Spilt inductance (mH) 63.74 Rated current 555.6A Table 3. 3 Protection CT and PT ratio

CT Parameter CT position Ct Ratio Type Connection Outer CT 1500/1 __ Y Inner CT 800/1 __ DELATA VT Parameter VT Position VT Ratio Type Reactor HV side 33 0.11 __ / 푘푉 √3 √3

3.5.2 setting calculations relay types: PCS-9611, RCS-9647 3.5.2.1 Differential Protection relay • Setting of biased pickup current 푄 퐾 55 × 106 1 0.4 × 푡푐푟 × 푙 = 0.4 × × = 0.256 퐴 3 √3 × 푈푛 퐾ℎ √3 × 33 × 10 1500 • Setting of the instantaneous pickup current 푄 퐾 55 × 106 1 3 × 푡푐푟 × 푙 = 3 × × = 1.923 퐴 3 √3 × 푈푛 퐾ℎ √3 × 33 × 10 1500 • Restraint factor of percentage differential protection is set to 0.6

Chapter three methodology

• Ratio of the CT ratio of both side 퐾 퐾 800 1500 𝑖 ÷ 푙 = ÷ = 0.53 퐾ℎ 퐾ℎ 1 1

3.5.2.2 Overcurrent Protection relay • Setting of stage 1 pickup current 6 푄푡푐푟 퐾𝑖 55 × 10 1 3 × × = 3 × 3 × = 2.09 퐴 3 × 푈푛 퐾ℎ 3 × 33 × 10 800 The time delay is taken as 0.2s

• Setting of stage 2 pickup current 6 푄푡푐푟 퐾𝑖 55 × 10 1 1.5 × × = 1.5 × 3 × = 1.05 퐴 3 × 푈푛 퐾ℎ 3 × 33 × 10 800

The time setting is taken as 1.5s.

3.6 FC5 branch relay types: PCS-9611, RCS-9647 3.6.1 Parameters of FC5 branch Table 3. 4 The basic parameters of FC5 branch

Fundamental wave capacity 10.7MVar Maximum harmonic current I5 80A Rated voltage 33 Connect type double Y Series segment number in a single- 2 Shunt group number in a 4 phase capacitor (N) single-phase capacitor (M) Series number of capacitor unit(n) 6 Shunt number of capacitor unit 12 (m) Rated capacity of one capacitor 334 Actual installed capacity 16.0 (kVAR) (MVAR) System frequency 50 Hz Series inductance value 13.75 mH

Chapter three methodology

Table 3. 5 Protection CT and PT ratio

CT Parameter CT Position CT Ratio Type Connection Branch CT 300/1 — Y Bridge differential CT 10/1 — Y VT Parameter VT Position VT Ratio Type Reactor HV side 33 0.11 — — / 푘푉 √3 √3

3.6.2 setting calculations

3.6.2.1 Overcurrent Protection relay • Setting of stage 1 pickup current 6 푄퐹퐶5 퐾𝑖 10.7 × 10 1 3 × × = 3 × 3 × = 1.88 퐴 1.732 × 푈푛 퐾ℎ 1.732 × 33 × 10 300

The time setting is taken as 0.2s. • Setting of stage 2 pickup current 6 푄푡푐푟 퐾𝑖 10.7 × 10 1 1.5 × × = 1.5 × 3 × = 0.94 1.732 × 푈푛 퐾ℎ 1.732 × 33 × 10 300 time setting is taken as 1.5s.

3.6.2.2 Overvoltage Protection relay

1.2푈푝 = 132푉 The time setting is taken as 10s.

3.6.2.3 Under voltage Protection relay

0.6푈푝 = 66푉 The time setting is taken as 1.5s.

Chapter three methodology

3.6.2.4 Unbalanced Current Protection For given number of capacitors shown in Table 3. 4the current setting is given by 0.04A note that this setting is only an estimated value. The greater one of the estimated value ，the 0.1 A of experienced value is adopted. The time setting is taken as 0.1s.

3.6.2.5 Thermal Overload Protection relay

2 2 The based current (full current, up to 5th harmonic) 퐼퐵 = √퐼1 + 퐼5 = 203.6 퐴

K𝑖 1 퐼푏Set = 퐼퐵 × = 203.6 × = 0.68 A Kℎ 300 The time constant setting of the thermal overload protection 휏 = 30 푚ⅈ푛 The factor setting of the thermal overload protection

퐾푇푟푝 = 1.15 1.15 times of full current is used to trig the timer of the thermal overload protection.

3.7 FC7 branch relay types: PCS-9611, RCS-9647 3.7.1 Parameters of FC7 branch Table 3. 6 The basic parameters of FC7 branch Fundamental wave capacity 5.2MVar Maximum harmonic current I7 40A Rated voltage 33 Connect type double star Series segment number in a single- 2 Shunt group number in a single- 2 phase capacitor (N) phase capacitor (M) Series number of capacitor unit(n) 6 Shunt number of capacitor unit 12 (m) Rated capacity of one capacitor 334 Actual installed capacity (Mvar) 8.02 (kvar) System frequency 50 Hz Series inductance value 14.04 mH

Chapter three methodology

Table 3. 7 Protection CT and PT ratio

CT Parameter CT Position CT Ratio Type Connection Branch CT 200/1 — Y Bridge differential CT 10/1 — Y VT Parameter VT Position VT Ratio type Reactor HV side 33 0.11 — / 푘푉 √3 √3

3.7.2 setting calculations

3.7.2.1 Overcurrent Protection relay • Setting of stage 1 pickup current 6 푄퐹퐶7 퐾𝑖 5.2 × 10 1 3 × × = 3 × 3 × = 1.37 퐴 1.732 × 푈푛 퐾ℎ 1.732 × 33 × 10 200

The time setting is taken as 0.2s. • Setting of stage 2 pickup current 6 푄퐹퐶7 퐾𝑖 5.2 × 10 1 1.5 × × = 1.5 × 3 × = 0.69 퐴 1.732 × 푈푛 퐾ℎ 1.732 × 33 × 10 200 The time setting is taken as 1.5s.

3.7.2.2 Overvoltage Protection relay

1.2푈푝 = 132푉 The time setting is taken as 10s.

3.7.2.3 Under voltage Protection relay

0.6푈푝 = 60푉 The time setting is taken as 1.5s.

Chapter three methodology

3.7.2.4 Unbalance Current Protection For given number of capacitors shown in Table 3. 6 the current setting is given by 0.038A note that this setting is only an estimated value. The greater one of the estimated value ，the 0.1 A of experienced value is adopted. The time setting is taken as 0.2s.

3.7.2.5 Thermal Overload Protection The based current (full current, up to 7th harmonic)

2 2 퐼퐵 = √퐼1 + 퐼7 = 99.39 퐴

K𝑖 1 퐼푏Set = 퐼퐵 × = 99.39 × = 0.497 A Kℎ 200 The time constant setting of the thermal overload protection 휏 = 30 푚ⅈ푛

The factor setting of the thermal overload protection

퐾푇푟푝 = 1.15 1.15 times of full current is used to trig the timer of the thermal overload protection.

Chapter four Simulation and results

CHAPTER FOUR: Simulation and Results

4.1 Introduction

In this chapter simulation of SVC protection for mahadiya substation is provided. Many fault scenarios were created in order to study the behavior of the system protection equipment in all different sections of the SVC (power transformer, TCR branch, FC5 branch, FC7 branch and the auxiliary transformer). ETAP software is used to achieve this simulation.

ETAP (electrical transient analysis program) is electrical engineering software that is used to design or simulate all different configurations of power systems. ETAP has been designed and developed by engineers to handle the diverse discipline of power systems for a broad spectrum of industries in one integrated package with multiple interface views such as AC and DC networks, cable raceways, ground grid, GIS, panels, arc-flash, protective device coordination/selectivity, and AC and DC control system diagrams.

4.2 ETAP simulation circuit Number of relays have been used in this simulation as shown in Figure 4. 1 SVC simulated circuit single line diagram:

1. Multi-functions relays from different manufactures have been used as an over-current relay (relay 2,4,6,9 ,10,14 & 15) in different branches. These multi-functions relays can be used to simulate different types of relays such as over-current, thermal, differential and earth fault. Relays (14,15) have been an earth fault relays.

In Figure 4. 1 SVC simulated circuit single line diagram, multi-functions relays have been used as thermal relays in the FC5 branch (relay 9) and the FC7branch (relay 10).

2. Voltage relays (relay VR2,3 & VR4) has been used in this circuit. These relays must be connected to the secondary of the VT and it’s used to perform the over-voltage and the under-voltage protection.

Chapter four Simulation and results

3. Differential relays (relay 3 &8) have been used to protect both the power transformer and the TCR branch. in the ETAB software this relay is (ideal) which means that the inrush current effect is neglected and time of operation is set to zero.

On the TCR branch, we simulated the thyristor valve using a switch, this switch is controlled by a voltage relay (VR4).

Figure 4. 1 SVC simulated circuit single line diagram

4.3 Over current relays coordination Figure 4. 2. Note that time difference between these relays must not be less than 250ms.

Chapter four Simulation and results

Figure 4. 2 over current relays coordination

4.4 Auxiliary transformer protection A three-phase fault has been simulated in the branch of the auxiliary transformer as shown in Figure 4. 3 . it has been noticed that firstly, relay 5 will trip the auxiliary transformer circuit breaker and then the relay of the secondary winding of the power transformer (relay 4) will trip its breaker and after that the relay of the primary side of the power transformer (relay2) will trip its breaker as shown in Figure 4. 4

Chapter four Simulation and results

Figure 4. 3 three-phase internal fault in auxiliary transformer

Figure 4. 4 sequence of operation for three phase fault in the auxiliary transformer

Chapter four Simulation and results

4.5 TCR branch protection

A three-phase fault has been in simulated in the branch of TCR as shown Figure 4. 5

Figure 4. 5 three-phase internal fault in the TCR branch

First the differential relay (relay8) operate and then the over current relay of TCR (relay6) as shown in Figure 4. 6.

Chapter four Simulation and results

Figure 4. 6sequence of operation for three-phase fault in the TCR branch 4.6 FC5 branch protection

A three-phase fault has been simulated in the branch of FC5 as shown in Figure 4. 7

Figure 4. 7 three-phase internal fault in theFC5 branch

Note that the over-current relay of the FC5 branch (relay 9) will operate first. The voltage relays in the FC5 and FC7 branch operates due to the under-voltage also the thermal relay operates due to the over-loading as shown in Figure 4. 8:

Chapter four Simulation and results

Figure 4. 8 sequence of operation for three-phase fault in the FC5 branch The unbalanced current was represented by an earth fault in the fifth harmonics branch in order to study the operation of the unbalanced current protection as shown in Figure 4. 9

Figure 4. 9 Earth fault in the FC5 branch The earth fault relay (14) will trip the circuit breaker (CB6) as shown in Figure 4. 10

Figure 4. 10 Sequence of operation for earth fault in FC5 branch

Chapter four Simulation and results

4.7 FC7 branch protection

Figure 4. 11 three-phase internal fault in the FC7 branch

A three-phase fault has been simulated in the branch of FC7 as shown in Figure 4. 11.Note that the over current relay of FC7 branch (relay9) will operate first. voltage relays in the FC5 and FC7 branch operates due to the under-voltage, also the thermal relay operates due to over- loading as shown in Figure 4. 12

Chapter four Simulation and results

Figure 4. 12 sequence of operation for three-phase fault in the FC7 branch

The unbalanced current was represented by an earth fault in the seventh harmonics branch in order to study the operation of the unbalanced current protection as shown in Figure 4. 13.

Figure 4. 13 Earth fault in the FC7 branch The earth fault relay (15) will trip the circuit breaker (CB7) as shown in Figure 4. 14.

Figure 4. 14 Sequence of operation for earth fault in FC7 branch

Chapter four Simulation and results

4.8 Power transformer protection

Figure 4. 15 Three-phase internal fault in power transformer The three-phase fault has been simulated as shown in Figure 4. 15, the differential relay (relay 3) operates first and trip its circuit breaker, then the over-current relays (relay 2 & 4) operates. these relays operate and trip their circuit breakers as shown in Figure 4. 16.

Figure 4. 16 sequence of operation for three-phase fault in the power transformer

An earth fault in the secondary side has been simulated to study the earth fault protection relays response in both primary and secondary sides in order to study the operation of the unbalanced current protection as shown in Figure 4. 17.

Chapter four Simulation and results

Figure 4. 17 Earth fault in the secondary side of the power transformer relay (2 & 4) which are a multi-functions relays operate as an over-current relay and an earth fault relay and trip both (CB1 & CB2) as shown in Figure 4. 18

Figure 4. 18 Sequence of operation for earth fault in the secondary side the power transformer

Chapter 5 conclusion & future work

CHAPTER FIVE: Conclusion and future work

5.1 conclusion

SVCs is one of the important power system units it performs power factor correction, voltage regulation and enhance grid capacity and stability So, the protection of such unit is very important. MAHADIYA substation SVC has been taken as case study in this project the protection scheme of the SVC in this substation is achieved by using different types of relays such as differential, over-current, thermal and voltages relays to provide primary and backup protection.

ETAP software is used to simulate this protection scheme by using different multi-functions relays and different protection equipment (CTs, VTs and circuit breakers).

Different faults in different sections of simulated circuit were installed in order to study the behavior of protection system in abnormal condition.

It has been found that this protection scheme provides suitable setting for protection equipment in order to keep SVC safe in abnormal condition.

5.2 Recommendations and future work.

• It should be used larger sizes of capacitors, because the larger the size in the network the smaller the size of the station static VAR compensators (svc). • SVCs response is very fast for both over or under voltage conditions beside the noticeable reduce of network losses so it’s useful to be used more in the grid. • Engineers with significant experience in the field of compensators at stations must be hired for regular maintenance and to ensure that if any event of a malfunction happened. Immediate maintenance is provided. • To insure better performance for the SVC protection scheme time delayed over-current and over-voltage protection may be used to further enhance control system failure detection.

Chapter 5 conclusion & future work

• Better performance of protective relays can be achieved by using over current relays with standard inverse curve characteristic in the primary side of the power transformer rather than using three stages definite time relay.

References

[1] S. B. D. S. Manisha Jaswani1, "A STUDY OF REACTIVE POWER COMPENSATION IN TRANSMISSION SYSTEM," 2015.

[2] K. V. P. M. R. M. U. S. a. A. Bindeshwar Singh, "Introduction to FACTS Controllers: A Technological Literature Survey," 2012.

[3] P. KUNDUR, POWER SYSTEM AND STABILITY AND CONTROL.

[4] F. Espace, Network Protection and automation guide, 2002.

[5] C. Strauss, Practical network automation and communication systems.

[6] M. B. W. K. Halonen, Protection of Static VAR Compensator, 2009.

Appendix A relays settings

Appendix A

Figure A. 1 Differential relay setting

Figure A. 2 Over-current relay in the 110-kV side stage one setting

Appendix A relays settings

Figure A. 3 Over-current relay in the 110-kV side stage two setting

Figure A. 4 Over-current relay in the 110-kV side stage three setting

Appendix A relays settings

Figure A. 5 Over–current relay stage one setting for auxiliary transformer

Figure A. 6 Over-current relay stage one setting for TCR branch

Figure A. 7 Over-current relay stage one setting for FC5 branch

Figure A. 8 Thermal relay setting for the FC5 branch

Appendix A relays settings

Figure A. 9 Voltage relay setting for the FC5 branch

Figure A. 10 Unbalance current protection setting for the FC5 branch

Figure A. 11 Over-current relay stage one setting for the FC7 branch

Appendix A relays settings

Figure A. 12 Thermal relay setting for the FC7 branch

Figure A. 13 Voltage relay setting for the FC7 branch

Figure A. 14 Unbalance current protection for the FC7 branch